Recovering hydrocarbons from subterranean zones typically involves drilling wellbores.
Wellbores are made using surface-located drilling equipment which drives a drill string that eventually extends from the surface equipment to the formation or subterranean zone of interest. The drill string can extend thousands of feet or meters below the surface. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. Drilling fluid, usually in the form of a drilling “mud”, is typically pumped through the drill string. The drilling fluid cools and lubricates the drill bit and also carries cuttings back to the surface. Drilling fluid may also be used to help control bottom hole pressure to inhibit hydrocarbon influx from the formation into the wellbore and potential blow out at surface.
Bottom hole assembly (BHA) is the name given to the equipment at the terminal end of a drill string. In addition to a drill bit, a BHA may comprise elements such as: apparatus for steering the direction of the drilling (e.g. a steerable downhole mud motor or rotary steerable system); sensors for measuring properties of the surrounding geological formations (e.g. sensors for use in well logging); sensors for measuring downhole conditions as drilling progresses; one or more systems for telemetry of data to the surface; stabilizers; heavy weight drill collars; pulsers; and the like. The BHA is typically advanced into the wellbore by a string of metallic tubulars (drill pipe).
Modern drilling systems may include any of a wide range of mechanical/electronic systems in the BHA or at other downhole locations. Such electronics systems may be packaged as part of a downhole probe. A downhole probe may comprise any active mechanical, electronic, and/or electromechanical system that operates downhole. A probe may provide any of a wide range of functions including, without limitation: data acquisition; measuring properties of the surrounding geological formations (e.g. well logging); measuring downhole conditions as drilling progresses; controlling downhole equipment; monitoring status of downhole equipment; directional drilling applications; measuring while drilling (MWD) applications; logging while drilling (LWD) applications; measuring properties of downhole fluids; and the like. A probe may comprise one or more systems for: telemetry of data to the surface; collecting data by way of sensors (e.g. sensors for use in well logging) that may include one or more of vibration sensors, magnetometers, inclinometers, accelerometers, nuclear particle detectors, electromagnetic detectors, acoustic detectors, and others; acquiring images; measuring fluid flow; determining directions; emitting signals, particles or fields for detection by other devices; interfacing to other downhole equipment; sampling downhole fluids; etc. A downhole probe is typically suspended in a bore of a drill string near the drill bit.
A downhole probe may communicate a wide range of information to the surface by telemetry. Telemetry information can be invaluable for efficient drilling operations. For example, telemetry information may be used by a drill rig crew to make decisions about controlling and steering the drill bit to optimize the drilling speed and trajectory based on numerous factors, including legal boundaries, locations of existing wells, formation properties, hydrocarbon size and location, etc.
In directional drilling operations the drill bit is steered to cause the wellbore to follow a curved trajectory. In some cases the drill bit is rotated by a mud motor located in the BHA. A portion of drill string above the drill bit may have a bend in it which can be oriented to push or deflect the drill bit in a desired direction.
In order to control drilling so that the wellbore follows a desired trajectory it is valuable if not essential to have information about the current orientation of the drill bit. A crew may make intentional deviations from the planned path as necessary based on information gathered from downhole sensors and transmitted to the surface by telemetry during the drilling process. This information may be transmitted and acted upon in real time or near real-time. The ability to obtain and transmit reliable data from downhole locations allows for relatively more economical and more efficient drilling operations.
There are several known telemetry techniques. These include transmitting information by generating vibrations in fluid in the bore hole (e.g. acoustic telemetry or mud pulse (MP) telemetry) and transmitting information by way of electromagnetic signals that propagate at least in part through the earth (EM telemetry). Other example telemetry techniques use hardwired drill pipe, fibre optic cable, or drill collar acoustic telemetry to carry data to the surface.
MP telemetry involves creating pressure waves in the circulating drill mud in the drill string. In MP telemetry, information may be transmitted by creating a series of pressure waves in the mud column. This may be achieved by changing the flow area and/or path of the drilling fluid as it passes a downhole probe in a timed, coded sequence, thereby creating pressure differentials in the drilling fluid. The pressure differentials or pulses may either be negative pulses and/or positive pulses or continuous wave. The pulses travel to surface where they may be detected by transducers in the surface piping. The detected pulses can then be decoded to reconstruct the data sent from the downhole probe. One or more signal processing techniques may be used to separate undesired mud pump noise, rig noise or downward propagating noise from upward (MWD) signals. The best data transmission rate achievable by current MP telemetry is about 40 bit/s. However, the achievable data rate falls off with increasing depth. It is not uncommon for MP data rates from deeper locations to be on the order of 1 to 2 bit/s.
A typical arrangement for EM telemetry uses parts of the drill string as an antenna. The drill string may be divided into two conductive sections by including an insulating joint or connector (a “gap sub”) in the drill string. The gap sub is typically placed at the top of a bottom hole assembly such that metallic drill pipe in the drill string above the BHA serves as one antenna element and metallic sections in the BHA serve as another antenna element. Electromagnetic telemetry signals can then be transmitted by applying electrical signals between the two antenna elements. The signals typically comprise very low frequency AC signals applied in a manner that codes information for transmission to the surface (higher frequency signals are typically attenuated more strongly than low frequency signals). The electromagnetic signals may be detected at the surface, for example by measuring electrical potential differences between the drill string or a metal casing that extends into the ground and one or more ground electrodes.
Advantages of EM telemetry relative to MP telemetry include generally faster data rates, increased reliability due to no moving downhole parts, high resistance to lost circulating material (LCM) use, and suitability for air/underbalanced drilling. An EM system can transmit data without a continuous fluid column; hence it is useful when there is no drilling fluid flowing. This is advantageous when a drill crew is adding a new section of drill pipe as the EM signal can transmit information (e.g. directional information) while the drill crew is adding the new pipe. Disadvantages of EM telemetry include lower depth capability, incompatibility with some formations (for example, high salt formations and formations of high resistivity contrast). Also, as the EM transmission is strongly attenuated over long distances through the earth formations, it may require a relatively large amount of power for the signals to be detected at surface. The electrical power available to generate EM signals may be provided by batteries or another power source that has limited capacity.
Drill rig operators sometimes provide in a drill string multiple independently-operating telemetry systems, each coupled with sensor systems such that each telemetry system communicates to a surface receiver readings collected by the sensor systems with which it is coupled. This requires substantial duplication of parts and additional batteries in the BHA, resulting in increased length of the BHA, increased cost, and (insofar as the sensors are necessarily positioned further away from the drill bit in the elongated BHA) decreased relevance of sensor readings. Furthermore, such known multiple telemetry systems are not optimized for performance, reliability, and efficient use of power.
One challenge facing designers of downhole telemetry systems is to achieve acceptably high data rates. Especially when attempting telemetry from locations that are deep in a wellbore, data rates can be so slow that transmitting even relatively small amounts of data can take long times, e.g. several minutes. This interferes with the goal of maintaining real time control over the drilling operation and creates a bottleneck which can slow the progress of drilling. It would be of great benefit to the industry to provide ways to achieve higher rates of transmission of telemetry data.
Another challenge facing the industry is improving the reliability of telemetry equipment. This problem is exacerbated because the downhole environment is typically harsh—being characterized by high pressures, high flow rates of potentially erosive drilling mud, high temperatures and/or extreme vibration. These conditions stress equipment, especially electronic equipment. It would be of great benefit to the industry to provide fault-tolerant/fault-resistant telemetry systems.
Another challenge facing the industry is to extend the run-time of downhole equipment. Many downhole electronic systems are battery-powered. Batteries tend to be more reliable than downhole power generators. However, batteries have limited capacity. Tripping equipment out of a wellbore to replace batteries is time-consuming and expensive. Methods and apparatus which can allow battery-powered downhole electronic systems to function for longer times between replacing batteries would be of great value.
There remains a need for downhole telemetry systems and methods that ameliorate at least some of the disadvantages of existing telemetry systems.